A variety of methods have been proposed to capture CO2 including solvent, sorbent, and membrane methods. Among solvent methods, chemical and physical methods have been suggested for the pre-combustion and post-combustion capture of CO2, respectively. At low CO2 partial pressures of about 0.01-0.015 MPa associated with post-combustion capture of CO2 from flue gas, amine solutions are favored because they will react with dilute concentrations of CO2. For example, a 30 wt % solution of monoethanolamine (MEA) in water will bind CO2 as a water-soluble ammonium carbamate at a 2:1 molar ratio of MEA:CO2, enabling this solution to absorb about 11 wt % CO2. CO2 release and solvent regeneration is accomplished via heating (Porcheron et al. 2011, MacDowell et al. 2010). A listing of references cited herein is provided hereinbelow.
In contrast, pre-combustion capture of CO2 is typically accomplished with physical solvents, given that the high partial pressure of CO2 in the fuel gas stream is sufficient to dissolve significant amounts of CO2 into the solvent without the need for chemical reaction. For example, at 25° C., if the partial pressure of CO2 is about 1 MPa, about 5 wt % CO2 will dissolve in the polymeric Selexol™ that is commonly employed for low temperature CO2 absorption. Regeneration of the solvent and release of the CO2 can be accomplished with temperature increase and/or pressure reduction.
Numerous small volatile compounds such as methanol and acetone (Miller et al. 2011) and oligomers or polymers have been considered as physical CO2 solvents (Miller et al. 2009). The most common polymeric CO2 solvent is based on an extremely hydrophilic polymer, polyethyleneglycol dimethylether (PEGDME). For example, the solvent used in the Selexol™ process (McKetta and Cunningham, 1995, Reighard et al. 1996) is a proprietary formulation that is rich in PEGDME. Given that the CO2 solvent strength of PEGDME increases with decreasing temperature and increasing pressure, it is not surprising that in most IGCC plant designs (IGCC is Integrated Gasification Combined Cycle), the CO2 absorption is typically conducted at high pressure and low temperature (about 40° C.); at these conditions most of the water vapor in the post-WGSR stream has been condensed and separated from the CO2- and H2-rich gas stream that is fed to the absorption column. Therefore the complete miscibility of PEGDME and water is not problematic because there is very little water vapor (on a mass basis) in the gas entering the absorption column even though the gas is saturated with water.
However, the energetic and capital costs associated with cooling the fuel gas stream to 40° C. are substantial. Consider a typical IGCC fuel gas stream (31 mol % CO2, 43% H2, 23% H2O, and 3% of other gases such CO, COS, H2S) leaving the WGSR (WGSR is water gas shift reaction) at 250° C. and 5.5 MPa. The stream could be cooled isobarically to its dew point of about 180° C. before its gas phase composition would change as water began to condense. Process modeling at the US DOE NETL has indicated that if CO2 can be selectively removed from within the WGSR or from the post-WGSR stream with little or no cooling, and if the remaining H2—H2O gas mixture is combusted to generate the hot, high pressure gas stream that is expanded in the gas turbine, the IGCC plant thermal efficiency could increase by 2-3 percentage points.
There would be large advantages in identifying physical solvents for selective CO2 capture from a hot or warm high pressure gas stream rich in CO2, H2O and H2. The main disadvantage of PEGDME for this higher temperature absorption is its complete miscibility with water. PEGDME-rich solvents, such as Selexol™, would remove both the water and the CO2 from the hot, humid fuel gas.
Although phase behavior studies involving polymeric solvents have been conducted, most reports focus on CO2 solubility at low temperature. For example, a prior study of phase behavior at 25° C. (Miller et al., 2009) considers PEGDME 250 and three hydrophobic polymers, polypropyleneglycol dimethylether based on the branched (1,2 propanediol) monomer (PPGDMEb 230), perfluoropolyether (PFPE 960), and polydimethylsiloxane (PDMS 237). (In each case the average molecular weight of the polymer is provided after its acronym.) Concerning hydrophobicity, PDMS and PFPE are completely immiscible with water, PEGDME is completely miscible with water in all proportions, and PPGDMEb absorbs several weight percent water at ambient temperature. When CO2 solvent strength is assessed on a weight percentage basis, PEGDME and PPGDMEb are comparable CO2 solvents. PDMS dissolves slightly less CO2 than the polyethers at the same temperature and pressure, and PFPE absorbs significantly less CO2 (Miller et al. 2009). The solubility of CO2 in polyethylene glycols of varying molecular weight, ranging from ethylene glycol monomethyl ether up to PEGDME 250 has also been reported at temperatures up to 60° C. (Henni et al., 2005). An earlier paper (Xu et al. 1992) reported similar results for the solubility of CO2 in Selexol™. The solubility of CO2 in a fluorinated silicone oil, trifluoropropylmethylsiloxane, with a kinematic viscosity of 300 centistokes has also been determined (Wedlake and Dobinson, 1979). The CO2-philicity of all of these solvents is attributable to multiple, favorable Lewis acid:Lewis base interactions between CO2 and the monomeric unit of each polymer.
A need exists to develop hydrophobic solvents that would absorb as much CO2 and as little H2O and H2 as possible at temperatures above 40° C. for efficient capture of CO2. More particularly, a need exists to provide better compounds, compositions, solvents, and processes for separation of gases at appropriate temperature and under industrial process conditions, including addressing the issues of water noted above and improving on existing ethylene-glycol based processes, compounds, and compositions. Examples of prior art are US Pat. Pub. 2013/0310569. See also, M. B. Miller, et al., Fluid Phase, Equil. 287, 26-32 (2009); M. B. Miller, et al., Energy Fuels, 24, 6214-6219 (2010); and Kovvali et al., Ind. Eng. Chem. Res., 41 (2002), 2287-2295.